This application is directed to nuclear magnetic resonance (NMR) logging, in particular to a method and system for in-situ calibration and even more particularly to calibrated transformations, which can be applied to NMR logs to quantify non-producible water in hydrocarbon-bearing reservoirs.
Due to the environmental and economic factors, the oil and gas industry typically conducts comprehensive evaluation of underground hydrocarbon formations to predict their producibility. Formation evaluation, also know as logging, determines potential performance of a hydrocarbon reservoir at the early stages of its development thus minimizing both the environmental impact and financial investment associated with further reservoir development. Known subsurface geological evaluation techniques include sonic logging, gamma ray logging, and electric logging. Recently, however, progress in nuclear spectroscopy and borehole imaging resulted in the development of a nuclear magnetic resonance (xe2x80x9cNMRxe2x80x9d) well-logging technology, which ensures environmentally safe formation logging that is unaffected by variations in the matrix mineralogy.
The principle underlying the NMR logging is that an assembly of magnetic moments, such as those of hydrogen nuclei, when exposed to a static magnetic field, aligns along the direction of the magnetic field. Upon consequent application of an oscillating magnetic field, the direction of the magnetic moments is tipped into the transverse plane. Upon cessation of the oscillating magnetic field, the magnetic moments precess to their original alignment thus generating a magnetic echo. The alignment time of the magnetic moments in the static magnetic field, also known as longitudinal or spin-lattice relaxation time, is characterized by a time constant T1. The alignment time due to the loss of coherence of the magnetic moments in the oscillating magnetic field, also known as transverse or spin-spin relaxation time, is represented by a time constant T2. These relaxation parameters are generally used to estimate, inter alia, saturation, porosity, permeability, as well as the type and amount of fluids that will be produced from a well. NMR measurements of these and other parameters of the geologic formation can be done using, for example, the centralized MRIL(trademark) tool made by NUMAR, a Halliburton company. The MRIL(trademark) tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications such G. R. Coates, L. Xiao, and M. G. Prammer, xe2x80x9cNMR Logging Principles and Applicationsxe2x80x9d, 2000, Butterworth-Heinemann. Details of the structure and the use of the MRIL(trademark) tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200 and 5,696,448, all of which are commonly owned by the assignee of the present invention. The content of the above patents and publications is hereby expressly incorporated by reference.
One of the earliest and still the most widely used applications of NMR logging is estimating the bulk volume of irreducible water (BVI) of reservoir formations. It allows the user to partition porosity into static and dynamic quantities, those fluids that will be held to the rock and fluids that will be produced. BVI also provides information needed to compute permeability using a popular equation developed by Coates and Denno in xe2x80x9cThe Producibility Answer Product.xe2x80x9d Current NMR methods used to determine BVI, such as cutoff-BVI and spectral-BVI, however, do not adequately incorporate capillary pressure, which is an essential feature of geological formation. An NMR bases method for determining BVI as a function of reservoir""s capillary pressure would expand the scope of uses of NMR data, such as predicting free water levels, water block due to aqueous phase drilling and/or completion fluid retention, capillary pressure curves, more accurate determination of movable fluid and accurate determinations of hydrocarbon pore volume.
The cutoff BVI model (CBVI) is based on the observation made by Timur in xe2x80x9cPulsed nuclear magnetic resonance studies of porosity, movable fluid and permeability of sandstones,xe2x80x9d that short relaxation times represent capillary bound fluids (BVI) and longer relaxation times represented free fluid index (FFI). Using a three component model and a xe2x80x9ccritical spin-lattice relaxation timexe2x80x9d of 12 milliseconds, he achieved a good match to core derived irreducible saturation values using an air/brine displacement pressure of 50 psi. In 1990 Miller et al. in xe2x80x9cSpin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determinationxe2x80x9d, introduced a logging system that employed static and radio frequency magnetic fields capable of measuring spin-echo magnetic resonance to determine porosity. BVI was determined by fitting the spin-spin echo data using a bi-exponential equation constrained to a time gate of 21 milliseconds. Following the work of Timur the time gate method recognized that early echoes decayed rapidly due to high surface area pores that hold water to the rock""s surface. The particular time selected was based on a best match to core derived irreducible saturations. However, the capillary pressure used to achieve this condition was not specified.
Recognizing that valuable information could be obtained with regard to pore size distribution and fluid types exponential fitting methods evolved into multi-exponential inversion. As a result, a relaxation time cutoff parameter of 25 to 46 milliseconds was implemented to obtain BVI. Following Timur, the cutoff value was selected based on comparisons to core measurements. Straley et al. in xe2x80x9cNMR in Partially Saturated Rocks: Laboratory Insights on Free Fluid Index and Comparison With Borehole Logsxe2x80x9d selected a T1 cutoff of 46 millisecond for samples that had been centrifuged using an air/brine pressure of 100 psi. Dunn et al. in xe2x80x9cOn the Calculation and Interpretation of NMR Relaxation Time Distributionsxe2x80x9d concluded that a T1 cutoff of 33 milliseconds compared best to samples de-saturated to an air/brine pressure of 400 psi. Morriss et al. in xe2x80x9cField Test of an Experimental Pulsed Nuclear Magnetism Toolxe2x80x9d found that a 27-millisecond T2 cutoff best approximated BVI when compared to core measured saturations centrifuged using an air/brine pressure of 50 psi. Prammer in xe2x80x9cNMR Pore Size Distributions and Permeability at the Well Sitexe2x80x9d selected a 25 to 30 millisecond cutoff based on a best match between core measured brine permeability and computed NMR permeability using the free fluid model.
Subsequent studies report the relaxation time cutoff varied depending on lithology and mineral content. A notable comparison is the study of two carbonate formations one in west Texas described by Chang et al. in xe2x80x9cEffective Porosity, Producible Fluid and Permeability in Carbonates from NMR Loggingxe2x80x9d and the other a Middle East carbonate described by Kenyon et al. in xe2x80x9cA Laboratory Study of of Nuclear Magnetic Resonance Relaxation and its Relation to Depositional Texture and petrophycical Propertiesxe2x80x94Carbonate Thamama Group, Mubarraz Field, Abu Dhabi.xe2x80x9d Chang et al. studied dolomitic carbonates and found that a 92-millisecond T2 cutoff best fit samples centrifuged using an air/brine pressure of 100 psi. In contrast to this, Kenyon et al. found carbonate samples from the Mubarraz Field yielded a relaxation time cutoff of 190 milliseconds when de-saturated using an air/brine capillary pressure of 25 psi.
Coates et al. in the paper entitled: xe2x80x9cA New Characterization of Bulk-Volume Irreducible Using Magnetic Resonance,xe2x80x9d however, identified that CBVI model has several limitations. In particular, the model is susceptible to textural and lithological variations, because it relies on the assumption that smaller pores remain at 100% saturation and the cutoff value represents a threshold size of pore that limits drainage. As a result, Coates et al. developed a spectral BVI (SBVI) model that emulates films of water left in pores after drainage. SBVI minimizes two shortcomings of the cutoff T2 model. First, it is not as susceptible to variations in textural and lithologic variation. Second, it overcomes the problems associated with certain lithofacies when flushed with water-base mud filtrate. For example, when quartz rich sandstones are flushed with water base muds, the hydrogen protons in the water phase are less restricted by the water/hydrocarbon interface and are weakly coupled to the smooth surface of the quartz grains. This causes longer than expected relaxation times. In such cases, a BVI determined using a CBVI model is often underestimated.
The SBVI model is based on the premise that each pore size has its own inherent irreducible water saturation. Given that relaxation time is related to pore size, this method utilizes core NMR measurements to relate each relaxation time to a specific fraction of capillary bound water. Thus, the bulk volume irreducible becomes a direct output of the inversion of the echo data, and it utilizes the entire T2 distribution. A notable feature of the SBVI model is that the boundary between bound and free fluid components as a smoothly decreasing function of pore size and, hence, T2. This subdivision of the T2 spectrum follows naturally from the assumption that pores are water-wet and contain a layer of irreducible water on their surfaces. Thus, pores of all sizes contribute to the total volume of irreducible water, not just the smallest pores in the rock.
Another essential feature of the SBVI model is the specification of the set of weight factors that defines the FFI-BVI boundary. In his paper, Coate et al. investigates two approaches in deriving equations for weight factors applicable to an arbitrary set of basis T2 times. One approach, which is considered to be more closely aligned with traditional capillary pressure theory then the above-described CBVI method, is to model the rock pore system as a bundle of water-wet capillary tubes and to derive an explicit expression for the pore-level saturation as a function of capillary pressure and various parameter. This model is expressed in the following equation:                                                         S              WIRR                        ⁡                          (                              T                2                            )                                =                                                    T                                  2                  ⁢                                      xe2x80x83                                    ⁢                  IRR                                                            T                2                                      ⁢                          xe2x80x83                        ⁢                          (                              2                -                                                      T                                          2                      ⁢                                              xe2x80x83                                            ⁢                      IRR                                                                            T                    2                                                              )                                      ⁢                  
                ⁢        where        ⁢                  
                ⁢                                            T                              2                ⁢                                  xe2x80x83                                ⁢                IRR                                      =                          σ                                                ρ                  2                                ⁢                                  xe2x80x83                                ⁢                                  P                  CIRR                                                              ,                                    (                  Eq          .                      xe2x80x83                    ⁢          1                )            
SWIRR is an irreducible water saturation, "sgr" is the interfacial tension between water and the non-wetting fluid, and xcfx812 is the surface relaxivity. A more detailed discussion of the SBVI model is presented in Appendix A.
The above-described BVI models require numerous core-specific parameters which are typically obtained by calibration against core data. To this end, laboratory NMR measurements performed on samples of core material are often used to obtain such parameters so that calibrated capillary-bound water (BVI) determinations can be made from NMR logs. These samples are usually selectively drilled and removed from a much larger core retrieved from the formations of interest. The extracted samples are cleaned and saturated with brine prior to making an initial laboratory NMR measurement. Then, each sample is de-saturated to a pre-determined capillary pressure condition and re-measured with a laboratory NMR spectrometer. In some instances, the samples may be de-saturated to more than one capillary pressure condition followed by a lab spectrometer measurement. Data from these experiments is then used to derive a calibrated transformation that can be applied to the saturated measurements (and NMR logs in the same formations) to derive the irreducible, or capillary-bound, water volume in the same, or similar, formations.
The success of this approach depends on several factors, such as formation homogeneity, the number of samples measured, the choices of de-saturation conditions, and the presence of secondary porosity features, such as fractures and vugs. Because of the above and other factors, laboratory NMR data obtained from core samples can involve errors. Such errors may adversely affect the derivation of calibrated BVI transformations intended for logging applications, especially when the core material does not represent the reservoir""s heterogeneity. Those of skill in the art will appreciate that heterogeneous formations are often encountered in practice, thus limiting the utility of the prior art calibration approach.
In addition, a single de-saturation condition chosen in the prior art for the laboratory NMR measurements may not reflect the multiple capillary conditions under which the logging data may be acquired, thereby introducing a systematic error in log-derived BVI values. Finally, it will be appreciated that the customary method outlined above may not work at all when samples of core material are simply not available for laboratory NMR measurements.
Accordingly, there is a need for a new approach using customized calibrated BVI transformations to obtain accurate BVI determinations from NMR logs in hydrocarbon-bearing reservoirs, so that accurate results can be obtained in situations where customary laboratory NMR measurements may not be possible or practical. The novel approach of this invention can be employed as an alternative to the prior art approach outlined above when samples of core material may not be available to perform laboratory NMR measurements, and could potentially produce superior results in heterogeneous formations. Additionally, the disclosed invention permits several new or improved applications of NMR data. These include, but are not limited to, improved determinations of hydrocarbon pore volume, more accurate predictions of movable water, prediction and mapping of the reservoir""s free water level(s), pore size, capillary pressure curves and the prediction of fracture fluid retention that may cause severe permeability reductions.
The interested reader is directed to the disclosure of the following references for useful background information:
Borgia, G. C., 1994, xe2x80x9cA New Un-Free Fluid Index in Sandstones Through NMR Studiesxe2x80x9d, SPE 69th Annual Technical Conference and Exhibition, Sep. 25-28, SPE 28366.
Brownstein, K. R. and Tarr, C. E., 1979, xe2x80x9cImportance of Classical Diffusion in NMR Studies of Water In Biological Cellsxe2x80x9d, Phys. Rev. A, 19, pp 2446-2453.
Chang, D, Vinegar, H., Morriss, C., and Straley, C., 1994, xe2x80x9cEffective Porosity, Producible Fluid and Permeability in Carbonates from NMR Loggingxe2x80x9d, SPWLA 35th Annual Logging Symposium, June, paper A. Coates, G. R. and Denoo, S., 1981, xe2x80x9cThe Producibility Answer Productxe2x80x9d, Schlumberger Technical Review, 29 (2), pp. 55.
Coates, G. R., and Denno, S., 1981, xe2x80x9cThe Producibility Answer Productxe2x80x9d, Schlumberger Technical Review, 29 (2), pp.55.
Coates, G. R., Marschall, D., Mardon, D., and Galford, J.: xe2x80x9cA New Characterization of Bulk-Volume Irreducible Using Magnetic Resonance,xe2x80x9d paper QQ presented at the SPWLA 38th Annual Logging Symposium, Houston, Tex., Jun. 15-18, 1997.
Coates, G. R., Miller, M., Gillen, M., and Henderson, G., 1991, xe2x80x9cAn Investigation of a New Magnetic Resonance Imaging Logxe2x80x9d, SPWLA 32nd Annual Logging Symposium, June, paper DD.
Coates, G. R., Miller, D. L., Mardon, D., and Gardner, J. S., 1995, xe2x80x9cApplying Log Measurements of Restricted Diffusion and T2 to Formation Evaluationxe2x80x9d, SPWLA 36th Annual Logging Symposium, Jun. 26-29, paper P.
Dunn K J. LaTorraca, G. A., Warner, J. L., Bergman, D. J., xe2x80x9cOn the Calculation and Interpretation of NMR Relaxation Time Distributionsxe2x80x9d, 1994, SPE 69th Annual Technical Conference and Exhibition, Sep., 25-28, SPE 28367
Dodge W M. S. Sr., Shafer, J. L., and Guzman-Garcia, A. G., xe2x80x9cCore and Log NMR Measurements of an Iron-rich, Glauconitic Sandstone Reservoirxe2x80x9d, 1995, SPWLA 36th Annual Logging Symposiums, Jun. 26-29, Paper O.
Hassler, G. L., and Brunner, E., 1945, xe2x80x9cMeasurements of Capillary Pressure in Small Core Samplesxe2x80x9d, Trans. AIME, 160, 114-123.
Kenyon, W. E., Takezaki, H., Straley, C., Sen, P. N., Herron, M., Matteson, Petricola, M. J., 1995, xe2x80x9cA Laboratory Study of of Nuclear Magnetic Resonance Relaxation and its Relation to Depositional Texture and petrophycical Properties-Carbonate Thamama Group, Mubarraz Field, Abu Dhabixe2x80x9d, SPE Middle East Oil Show, Bahrain, March 11-14, SPE 29886.
Kleinberg, R. L., Straley, C., Kenyon, W. E., Akkurt, R., and Farooqui, S. A., 1993, xe2x80x9cNuclear Magnetic Resonance of Rocks: T1 vs. T2xe2x80x9d, SPE 68th Annual Technical Conference and Exhibition, October 3-6, SPE 26470.
Kleinberg, R. L., 1994, xe2x80x9cPore Size Distributions, Pore Coupling, and Transverse Relaxation Spectra of Porous Rocksxe2x80x9d, Magnetic Resonance Imaging, 12 (2), pp. 271-274.
Latour, L. L., Kleinberg, R. L., and Sezginer, A., 1992, xe2x80x9cNuclear Magnetic Resonance Properties of Rocks at Elevated Temperaturesxe2x80x9d, J. Colloid Interface, Sci., 150, pp.535-548.
Marschall, D. M.: xe2x80x9cHBVIxe2x80x94An NMR Method to Determine BVI as a Function of Reservoir Capillarity,xe2x80x9d paper KK presented at the SPWLA 41st Annual Logging Symposium, Dallas, Tex. Jun. 4-7, 2000.
Marschall, D., Gardner, J. S., Mardon, D, and Coates, G. R., 1995, xe2x80x9cMethod for Correlating NMR Relaxometry and Mercury Injection Dataxe2x80x9d, Society of Core Analysts Conference, San Francisco, paper 9511.
Miller M. N., Palteil, Z., Gillen, M. E., Granot, J., and Bouton, J. C., xe2x80x9cSpin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determinationxe2x80x9d, 1990, SPE 65th Annual Technical Conference and Exhibition, Sep. 23-26, SPE 20561.
Morriss, C. E., MacInnis, R., Freedman, R, Smaardyk, J., 1993, xe2x80x9cField Test of an Experimental Pulsed Nuclear Magnetism Toolxe2x80x9d, SPWLA 34th Annual Logging Symposium, Jun. 13-16, paper GGG.
O""Meara, D. J., Hirasaki, G. J., and Rohan, J. A., 1992, xe2x80x9cCentrifuge Measurements of Capillary Pressure, Part 1-Outflow Boundary Conditionxe2x80x9d, SPE Reservoir Engineering, p.133-142.
Prammer, M. G., 1994, xe2x80x9cNMR Pore Size Distributions and Permeability at the Well Sitexe2x80x9d, SPE 69th Annual Technical Conference and Exhibition, Sep. 25-28, SPE 28368.
Straley, C., Morriss, C. E., Kenyon, W. E., and Howard, J. J., 1991, xe2x80x9cNMR in Partially Saturated Rocks: Laboratory Insights on Free Fluid Index and Comparison With Borehole Logsxe2x80x9d, SPWLA 32nd Annual Logging Symposium, June, paper CC.
Straley, C., Rossini, D., Vinegar, H., Tutunjian, P., Morriss, C., 1994, xe2x80x9cCore Analysis By Low Field NMRxe2x80x9d, Society of Core Analysts Conference, Stavanger, paper 9406.
Timur, A., 1967, xe2x80x9cPulsed nuclear magnetic resonance studies of porosity, movable fluid and permeability of sandstones,xe2x80x9d SPE 2045, 42nd Annual Meeting preprint, SPE. Later published in 1969 in Journal of Petroleum Technology, v. 21, no. 6, p. 775-786.
The NMR Sandstone Rock Catalogue, Applied Reservoir Technology, Ltd./Sintef Unimed, 1996.
The East Texas Sandstone Catalogue, NUMAR, MR Laboratory, 1996.
Accordingly, it is an object of the present invention to provide a data logging method and system that overcome problems associated with the prior art solutions, and help meet the market demands for increased input capacity, high distribution flexibility and fault tolerance. The novel approach used in accordance with the present invention combines in situ NMR logging measurements from one or more well bores with measurements obtained from routine and special core analysis methods applied to rock samples recovered by drilling/coring or wireline rotary sidewall coring operations. Conceptually, the approach proposed in this application involves several major phases. Initially, an empirical relationship between BVI and capillary pressure responses is established. Then, a calibration of NMR derived BVI based on conventional core data is performed to derive transformation model linking BVI and capillary pressure responses. Finally, the derived transformation model is applied to the NMR measurements to to quantify non-producible water in the NMR log.
Since present invention is based on the premise that there exists a relationship between BVI and capillary pressure, in accordance with a preferred embodiment, known BVI models were empirically analyzed to confirm such proposition. In particular, the dependance between BVI and capillary pressure is confirmed with core measurements. To this end, core samples from the Baker Hughes test well in Oklahoma were selected for study. Initially, various centrifuge and mercury injection capillary pressure tests, as well as low-field NMR measurements where conducted on the core samples. Then, several integration steps were performed on the core data derived from the above-described experiments. Finally, BVI dependancy on capillary pressure was established; particularly, it has been observed that both CVBI and SBVI models exhibit apparent logarithmic dependance on capillary pressure.
Once an empirical dependence between BVI and capillary pressure established, a transformation model directly linking BVI and capillary pressure is developed by calibrating NMR derived BVI with the core data. In particular, the novel transformation model utilizes SBVI and/or CBVI models to directly relate NMR derived BVI and capillary pressure responses through the height of the measurement in a borehole, hence it is named HBVI. In accordance with the transformation model, capillary pressure responses are related to height through the following equation: Pc=H(xcex4w,xe2x88x92xcex4h), where Pc represents capillary pressure, xcex4w is the pressure gradient for the water in the formation, xcex4h is the pressure gradient of the hydrocarbon, and H is the height, or distance the measurement is above the free water level. To facilitate the transformation, in accordance with a preferred embodiment, the NMR relaxation spectra are indexed by true vertical depth (TVD). Similarly, data from routine and special core analyses, such as the capillary pressure curves, are indexed by TVD.
In accordance with a preferred embodiment, once the transformation model is derived, it can be applied to the NMR measurements to quantify non-producible water in the NMR log. In particular, the HBVI transformation model enables capillary pressure responses from core analysis to define volume of hydrocarbons (and water) for points above the free water level at in situ conditions.
To this end the, in one aspect, the invention is a method for NMR borehole logging comprising the steps of: providing a core analysis of a borehole, the analysis comprising capillary pressure responses being indexed by a true vertical depth (TVD) in the borehole; providing a NMR log of a borehole, the NMR log being indexed by TVD; deriving a bound volume irreducible (BVI) transformation model calibrated on the basis of the provided core analysis; and applying the derived BVI transformation model to the NMR log of the borehole to quantify non-producible water in the NMR log.
In one aspect, the invention includes a method for deriving formation-specific HBVI functions when core material is available. In another aspect, to handle those situations when core material is not available, an alternative method, so called Global Solution, is disclosed to predict HBVI function for sandstone reservoirs. This method recognizes that NMR is highly sensitive to the surface area of the pore system. Sandstones that are more quartz rich have a higher probability of exhibiting low pore surface areas causing them to exhibit weaker surface relaxation. The analyst simply needs to estimate quartz richness, via log analysis techniques, or by direct laboratory measurement and assign an HBVI function to be used. When reliable mineral data is available regarding clay content and minerals known to exhibit fast relaxation times, an improved estimation method is also presented. These simple techniques allow the analyst to determine BVI from NMR logs for a specific capillary pressure or multiple capillary conditions. Additional aspects of the invention are disclosed in greater detail in the following description and the attached claims.